CALGARY, March 28, 2013 /CNW/ - Athabasca Oil Corporation (TSX: ATH)
announces that it has filed its Annual Information Form dated March 28,
2013, which can be retrieved electronically from the Company's website
(www.atha.com) or from SEDAR (www.sedar.com).

Athabasca is also pleased to report the highlights of an independent
reserves and resources evaluation, conducted by GLJ Petroleum
Consultants Ltd. and DeGolyer MacNaughton Canada Limited, of the
Company's thermal and light oil assets, at December 31, 2012.

Highlights include:

Reclassification of 51 million barrels ("bbl") of Hangingstone's
probable bitumen reserves to the proved reserve category, based upon
receipt of regulatory approvals and project sanctioning by the
Company's Board of Directors;

Proved plus probable bitumen reserves increased over the previous year's
estimate of 339 million bbl of bitumen (net of the disposition of the
MacKay River Joint Venture), to an estimated 342 million bbl; and

In 2012, Athabasca received regulatory approvals to construct the
Hangingstone Project 1, a 12,000 bbl/d SAGD project. The Company's
Board of Directors subsequently sanctioned the Hangingstone Project 1,
triggering the reclassification of 51 million bbl of Hangingstone's
probable reserves to the proved reserve category, effective December
31, 2012.

The Hangingstone project area is comprised of 136,000 acres of oil sands
leases which, based upon an independent engineering estimate, at
December 31, 2012, contain 51 million bbl of proved reserves, 66
million bbl of probable reserves and 0.9 billion bbl of contingent
resources (best estimate).

Year-over-year additions to the Thermal Oil Division's reserves and
resources reflect the successful results of the 2011-2012 Winter
Drilling and Seismic Program which further delineated the bitumen
deposits.

In March 2012, Athabasca closed the sale of its remaining 40-percent
interest in the MacKay River Joint Venture to Cretaceous Oilsands
Holdings Limited, which subsequently amalgamated with Phoenix Energy
Holdings Limited, a wholly-owned subsidiary of PetroChina Company
International Limited. The sale resulted in the divestiture of a
combined 114 million bbl of proved plus probable reserves and 573
million bbl (best estimate) of contingent resources.

At December 31, 2012, the Light Oil Division's reserves increased,
year-over-year, from 9.2 million boe of proved plus probable ("2P")
reserves to 22.0 million boe proved plus probable reserves. This
139-percent, year-over-year increase in Athabasca's 2P reserves
reflects a successful drilling and completion program in 2012 which
targeted stacked (or multi-zone) unconventional reservoirs in the
Duvernay and Montney formations.

At year-end, the Light Oil Division had established production from 33
horizontal wells in the Fox Creek area (Kaybob East, Kaybob West and
Saxon/Placid). Production facilities were commissioned in late 2012,
limiting the reporting period for well production histories. Artificial
lift has now been installed on the majority of the new wells, which is
expected to stabilize production rates.

As production trends and type curves are established in 2013, the
Company expects to prove reservoir recoveries and additional 2P
reserves. Additional wells were drilled in late 2012, but were not
completed or tested prior to year-end - production from these new wells
is expected to contribute additional 2P reserves in 2013. At year end
2012, Athabasca had just 30 percent of its proven light oil reserves
classified as Proven Undeveloped (PUD) locations.

Athabasca's strategy has been to secure egress and maximized net backs
for its product. As such, the Company invested a significant amount to
construct wholly owned infrastructure in the Kaybob and Simonette areas
during 2012, thereby reducing future costs, on a boe basis, as
production increases. The control of infrastructure is expected to
provide the Company with the flexibility to blend and market crude oil
and condensate, according to market demands, thereby increasing net
backs. Athabasca's 2012 capital program of $611 million included
approximately $189 million for facilities and $27 million for the
acquisition of petroleum and natural gas leases. The Company's 2013
capital budget includes an additional $38 million to construct the
infrastructure associated with year-end 2P reserves.

Athabasca expects to realize future cost reductions as it moves down the
learning curve, primarily through the drilling of multi-wells from
single pads. By leveraging its fixed operating costs - along with the
ability to blend oil with Duvernay condensate - the Company expects to
receive a premium netback for its product. These factors should provide
for a very competitive finding and development and recycle ratio for
future development plans at Fox Creek.

Light Oil Reserves at December 31, 2012

Reserves (millions of barrels of oil equivalent)

Proved

Probable

Proved + Probable

Kaybob

8.3

6.7

15.0

Saxon Placid

2.7

4.0

6.7

Exploration Area

0.2

0.1

0.3

Total

11.2

10.8

22.0

Athabasca's resources and reserves are situated within a land base that
is comprised of greater than 1.5 million acres (net) of oil sands
leases and permits held by the Thermal Light Oil Division and greater
than 2.8 million acres (net) of petroleum and natural gas leases held
by the Light Oil Division. During the past year, the Company's combined
Thermal Oil and Light Oil land base increased by approximately 19
percent, from 3.6 to approximately 4.3 million acres (net).

About Athabasca Oil Corporation

Athabasca is a dynamic, Canadian exploration and production company
focused on the development of oil resource plays in Alberta, Canada.
The Company has accumulated an extensive, high quality resource base
suitable for the extraction of thermal crude oil (bitumen) and light
oil. Well financed and well endowed with quality assets and talented
people, Athabasca is poised to become a major Canadian oil producer. It
aspires to produce more than 200,000 boe/d by 2020, comprised of a
50/50 weighting of thermal and light oil. Athabasca is traded on the
TSX under the symbol "ATH."

Reader Advisory:

This News Release contains forward-looking information that involves
various risks, uncertainties and other factors. All information other
than statements of historical fact is forward-looking information. The
use of any of the words "anticipate," "plan," "continue," "estimate,"
"expect," "may," "will," "project," "should," "believe," "predict,"
"pursue" and "potential" and similar expressions are intended to
identify forward-looking information. The forward-looking information
is not historical fact, but rather is based on the Company's current
plans, objectives, goals, strategies, estimates, assumptions and
projections about the Company's industry, business and future financial
results. This information involves known and unknown risks,
uncertainties and other factors that may cause actual results or events
to differ materially from those anticipated in such forward-looking
information. No assurance can be given that these expectations will
prove to be correct and such forward-looking information included in
this News Release should not be unduly relied upon. This information
speaks only as of the date of this News Release. In particular, this
News Release may contain forward-looking information pertaining to the
following: expected timing of receipt of first significant revenues
from the Company's assets; the Company's capital expenditure programs;
the estimated quantity of the Company's and Proved and Probable
Reserves and Contingent Resources; the Company's drilling plans; the
Company's plans for, and results of, exploration and development
activities; the Company's estimated future commitments; business plans;
development of the Company's Thermal Oil Division and Conventional Oil
and Gas Division projects; timing of facilities commissioning and the
receipt of the expected benefits therefrom: timing of production; the
use of in-situ recovery methods such as Steam Assisted Gravity Drainage
(SAGD) and Thermal Assisted Gravity Drainage (TAGD) for production of
recoverable bitumen, including the potential benefits of such methods;
targeted exit rate production for the first half of 2013 and beyond,
and long term production goals; timing of submission of project
regulatory applications; estimated timing of first steaming, selection
of equipment manufactures and internal sanction, as applicable, of the
Company's projects; estimated initial and full production of the
Company's projects; Athabasca's plans with respect to the Light Oil
Division's assets and the expected benefits to be received by Athabasca
from such assets; expectations regarding the Company's Light Oil
Division development areas including anticipated production levels and
timing of receipt of significant revenues and operating results
therefrom; and expected increase to number of staff members in 2013.

With respect to forward-looking information contained in this News
Release, assumptions have been made regarding, among other things: the
Company's ability to obtain qualified staff and equipment in a timely
and cost-efficient manner; the regulatory framework governing
royalties, taxes and environmental matters in the jurisdictions in
which the Company conducts and will conduct its business; the
applicability of technologies for the recovery and production of the
Company's reserves and resources; future capital expenditures to be
made by the Company; future sources of funding for the Company's
capital programs; the Company's future debt levels; geological and
engineering estimates in respect of the Company's reserves and
resources; the geography of the areas in which the Company is
conducting exploration and development activities; the impact that the
agreements relating to the PetroChina Transaction (the "PetroChina
Transaction Agreements") will have on the Company, including on the
Company's financial condition and results of operations; and the
Company's ability to obtain financing on acceptable terms.

Actual results could differ materially from those anticipated in this
forward-looking information as a result of the risk factors set forth
in the Company's most recent Annual Information Form filed on March 28,
2013 ("AIF") that is available on SEDAR at www.sedar.com, including, but not
limited to: fluctuations in market prices for crude oil, natural gas
and bitumen blend; general economic, market and business conditions;
dependence on Phoenix Energy Holdings Limited (" Phoenix") as the
joint venture participant in the Dover oil sands projects; variations
in foreign exchange and interest rates; factors affecting potential
profitability; factors affecting funding, including the development of
new business opportunities, the availability of financing, developments
in technology, the priorities of the Company and of its current and
future joint venture partners and general economic conditions; risk of
reassessments of the Company's tax filings by taxation authorities;
failure to satisfy certain conditions in connection with the Company's
debt and credit facilities; uncertainties inherent in estimating
quantities of reserves and resources; uncertainties inherent in SAGD
and TAGD; the potential impact of the exercise of the Dover put/call
options on the Company; failure to meet the conditions precedent to the
exercise by the Company of the Dover put option, including failure to
obtain necessary regulatory approvals for completion of the Dover
put/call option transaction in 2013 or at all; failure to obtain
regulatory approval for the Dover West Sands project, Dover West TAGD
Pilot project or other oil sands projects when anticipated or at all;
failure to meet development schedules and potential cost overruns;
increases in operating costs making projects uneconomic; the effect of
diluent and natural gas supply constraints and increases in the costs
thereof; gas over bitumen issues affecting operational results; the
potential for adverse consequences in the event that the Company
defaults under certain of the PetroChina Transaction Agreements;
environmental risks and hazards and the cost of compliance with
environmental regulations; failure to obtain or retain key personnel;
the substantial capital requirements of the Company's projects; the
need to obtain regulatory approvals and maintain compliance with
regulatory requirements; changes to royalty regimes; political risks;
failure to accurately estimate abandonment and reclamation costs; risks
inherent in the Company's operations, including those related to
exploration, development and production of oil sands, crude oil and
natural gas reserves and resources, including the production of oil
sands reserves and resources using SAGD and TAGD and the production of
crude oil and natural gas using multi-stage fracture and other
stimulation technologies; the potential for management estimates and
assumptions to be inaccurate; reliance on third party infrastructure
for project facilities; failure by counterparties (including without
limitation Phoenix) to comply with contractual arrangements between
the Company and such counterparties; the potential lack of available
drilling equipment and limitations on access to the Company's assets;
Aboriginal claims; seasonality; hedging risks; insurance risks; claims
made in respect of the Company's operations, properties or assets; the
potential for adverse consequences as a result of the change of control
provisions in the PetroChina Transaction Agreements; competition for,
among other things, capital, the acquisition of reserves and resources,
export pipeline capacity and skilled personnel; the failure of the
Company or the holder of certain licenses or leases to meet specific
requirements of such licenses or leases; risk of reassessments of the
Company's tax filings by taxation authorities; risks arising from
future acquisition and joint venture activities; risks that joint
venture arrangements will not perform as expected; volatility in the
market price of the common shares; and the effect that the issuance of
additional securities by the Company could have on the market price of
the common shares.

In addition, information and statements in this News Release relating to
"reserves" and "resources" are deemed to be forward-looking
information, as they involve the implied assessment, based on certain
estimates and assumptions, that the reserves and resources described
exist in the quantities predicted or estimated, and that the reserves
and resources described can be profitably produced in the future. The
assumptions relating to the Company's reserves and resources are
contained in the reports of GLJ Petroleum Consultants Ltd. and DeGolyer
and MacNaughton Canada Limited, each dated effective December 31, 2012.
For additional information regarding the specific contingencies which
prevent the classification of the Company's Contingent Resources as
Reserves see "Independent Reserve and Resource Evaluations - Contingent
Resources Estimates" in the AIF. The estimates of reserves and future
net revenue for individual properties in this New Release may not
reflect the same confidence level as estimates of reserves and future
net revenue for all properties, due to the effects of aggregation.
"Contingent Resources" has the meaning given to that term in the AIF.

The forward-looking statements included in this News Release are
expressly qualified by this cautionary statement. Athabasca does not
undertake any obligation to publicly update or revise any
forward-looking statements except as required by applicable securities
laws.

Oil and Gas Information:
"BOEs" may be misleading, particularly if used in isolation. A BOE
conversion ratio of six thousand cubic feet of natural gas to one
barrel of oil equivalent (6 Mcf: 1 bbl) is based on an energy
equivalency conversion method primarily applicable at the burner tip
and does not represent a value equivalency at the wellhead.